U.S. patent application number 15/385105 was filed with the patent office on 2017-04-13 for non-acidic exothermic sandstone stimulation fluids.
This patent application is currently assigned to Saudi Arabian Oil Company. The applicant listed for this patent is Saudi Arabian Oil Company. Invention is credited to Mohammed Nasser Al-Dahlan, Abdullah Mohammed Al-Harith, Ayman Raja Al-Nakhli.
Application Number | 20170101577 15/385105 |
Document ID | / |
Family ID | 47664427 |
Filed Date | 2017-04-13 |
United States Patent
Application |
20170101577 |
Kind Code |
A1 |
Al-Dahlan; Mohammed Nasser ;
et al. |
April 13, 2017 |
NON-ACIDIC EXOTHERMIC SANDSTONE STIMULATION FLUIDS
Abstract
Provided is a method and composition for the in-situ generation
of synthetic sweet spots in tight-gas formations. The composition
can include nitrogen generating compounds, which upon activation,
react to generate heat and nitrogen gas. The method of using the
composition includes injecting the composition into a tight-gas
formation such that upon activation, the heat and nitrogen gas
generated.
Inventors: |
Al-Dahlan; Mohammed Nasser;
(Al-Khouber, SA) ; Al-Nakhli; Ayman Raja; (Dammam,
SA) ; Al-Harith; Abdullah Mohammed; (Althoqbah,
SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Saudi Arabian Oil Company |
Dhahran |
|
SA |
|
|
Assignee: |
Saudi Arabian Oil Company
Dhahran
SA
|
Family ID: |
47664427 |
Appl. No.: |
15/385105 |
Filed: |
December 20, 2016 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
13744333 |
Jan 17, 2013 |
9556718 |
|
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15385105 |
|
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|
61587212 |
Jan 17, 2012 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C09K 8/72 20130101; C09K
8/845 20130101; E21B 43/166 20130101; C09K 8/607 20130101; C09K
8/62 20130101; E21B 43/24 20130101; E21B 43/25 20130101 |
International
Class: |
C09K 8/62 20060101
C09K008/62; E21B 43/24 20060101 E21B043/24; C09K 8/60 20060101
C09K008/60; E21B 43/25 20060101 E21B043/25 |
Claims
1. A non-acidic well stimulation composition for use in a sandstone
formation, the composition comprising: an ammonium ion containing
compound; a nitrite ion containing compound, wherein at least one
of the ammonium ion containing compound and nitrite ion containing
compound is encapsulated with an erodible coating such that a
reaction between the ammonium and nitrite ions is delayed in situ
until the ammonium ion containing compound and the nitrite ion
containing compound have migrated to within the sandstone
formation, and wherein the ammonium ion containing compound and
nitrite ion containing compound are present at concentrations
sufficient to generate heat and nitrogen gas upon reacting with one
another via an exothermic reaction within the sandstone formation;
and a non-acidic well stimulation fluid, wherein the non-acidic
well stimulation fluid comprises an alkali hydroxide or an alkaline
earth hydroxide, wherein the alkali hydroxide or alkaline earth
hydroxide is present at a concentration operable to dissolve at
least a portion of a sandstone formation without forming
precipitates, at an increased temperature caused by the exothermic
reaction between the ammonium ion containing compound and the
nitrite ion containing compound, for between greater than about 1
hour to about 12 hours.
2. The composition of claim 1, wherein the non-acidic well
stimulation fluid comprises sodium hydroxide.
3. The composition of claim 1, wherein the non-acidic well
stimulation fluid comprises at least about 5% sodium hydroxide by
weight.
4. The composition of claim 1, wherein the non-acidic well
stimulation fluid comprises at least about 10% sodium hydroxide by
weight.
5. The composition of claim 1, wherein the non-acidic well
stimulation fluid comprises at least about 15% sodium hydroxide by
weight.
6. The composition of claim 1, wherein the ammonium ion containing
compound is selected from the group consisting of: ammonium
chloride; ammonium bromide; ammonium nitrate; ammonium sulfate;
ammonium carbonate; ammonium hydroxide; and mixtures thereof.
7. The composition of claim 1, wherein the nitrite ion containing
compound is selected from the group consisting of: sodium nitrite;
sodium hypochlorite; and mixtures thereof.
8. The composition of claim 1, wherein the coating encapsulating at
least one of the ammonium ion containing compound and the nitrite
ion containing compound is a polymer selected from the group
consisting of: guar; chitosan; polyvinyl alcohol; and mixtures
thereof.
9. The composition of claim 1, wherein the coating encapsulating at
least one of the ammonium ion containing compound and the nitrite
ion containing compound is selected from the group consisting of:
carboxymethyl cellulose, xanthan, and mixtures thereof.
10. The composition of claim 1, wherein a molar ratio of the
ammonium ion containing compound to the nitrite ion containing
compound in the non-acidic well stimulation composition is between
about 1.1:1 and 1:1.1.
11. The composition of claim 1, wherein the ammonium ion containing
compound comprises ammonium chloride.
12. The composition of claim 1, wherein the nitrite ion containing
compound comprises sodium nitrite.
13. The composition of claim 1, wherein the ammonium ion containing
compound and nitrite ion containing compound are present in
sufficient concentrations to increase the temperature within the
sandstone formation by between about 50.degree. C. and 100.degree.
C.
14. The composition of claim 1, wherein the composition further
comprises an activator to activate the exothermic reaction between
the ammonium ion containing compound and the nitrite ion containing
compound, and wherein the activator is present at a concentration
such that the activator is consumed by the exothermic reaction
between the ammonium ion containing compound and the nitrite ion
containing compound.
Description
RELATED APPLICATION
[0001] This application is a divisional of and claims priority to
and the benefit of U.S. patent application Ser. No. 13/744,333,
filed on Jan. 17, 2013, which claims priority to U.S. Provisional
Patent Application No. 61/587,212 titled "Non-Acidic Exothermic
Sandstone Stimulation Fluids," filed on Jan. 17, 2012, the
disclosures of which are incorporated herein by reference in their
entirety.
FIELD OF THE INVENTION
[0002] This invention relates to oil and gas well stimulation and
compositions for the stimulation of hydrocarbon bearing oil and gas
containing formations. More specifically, the invention provides a
method for the stimulation of a hydrocarbon bearing oil or gas
formation wherein non-acidic stimulation fluids and exothermic
reactants are injected into the formation.
BACKGROUND OF THE INVENTION
[0003] The search for and recovery of oil is becoming increasingly
difficult as world-wide petroleum reserves decline. In many
instances, reserves trapped within certain low permeability
formations, such as certain sandstone, carbonate, and/or shale
formations, exhibit little or no production, and are thus
economically undesirable to develop at current oil and gas prices.
Well stimulation is one method that is frequently employed to
increase the net permeability of a formation or reservoir, thereby
leading to increased production from these wells that have little
or no production.
[0004] During well stimulation operations, chemicals can be
injected into the formation in a process known as well stimulation.
Some exemplary known stimulation techniques include: (1) injection
of chemicals into the wellbore wherein the chemicals react with
and/or dissolve production limiting conditions (e.g., the presence
of clays and drilling solids); (2) injection of chemicals through
the wellbore and into the formation to react with and/or dissolve
portions of the formation, thereby creating alternative flow paths
for recoverable hydrocarbons (e.g., acid-fracturing or
matrix-fracturing processes); and (3) high pressure injection of
water or chemicals through the wellbore and into the formation at
pressures that are sufficient to fracture the formation, thereby
creating new or additional flow channels through which hydrocarbons
can more readily move from the formation into the wellbore.
[0005] In certain tight reservoirs, well productivity is typically
low, thus making the well non-economical from a standpoint of
development. One commonly employed technique for stimulating low
productivity wells is hydraulic fracturing, which can involve the
injection of fluids, such as high viscosity fluids, into the well
at a sufficiently high rate so that enough pressure is built up
inside the wellbore to split the formation apart or fractures. The
resulting hydraulically induced fracture that is produced as a
result of the fracturing can extend from the wellbore deep into the
formation.
[0006] Sandstone formations can be particularly susceptible to
formation damage from formation minerals such as clay and other
siliceous deposits. Stimulation methods for these types of
formations have typically employed acid or acid-based fluids for
the treatment or stimulation due to the ability of the acid or
acid-based fluid to readily dissolve both formation minerals and
contaminants (e.g., drilling fluids that may be coating the
wellbore or that has penetrated into the formation) introduced into
the wellbore/formation during drilling or remedial operations.
[0007] The removal of formation minerals and other deposits, such
as clays, drilling solids, or precipitates, are key concerns in
well completion operations. As noted above, the known prior art
techniques typically involve acids, often highly concentrated acids
such as hydrofluoric acid (HF) and HCl--HF acid mixtures, which are
both highly corrosive and can create dangerous operating
conditions. In a typical HF based well stimulation, a preflush
solution that includes ammonium or potassium chloride is injected
into a well, followed by the injection of a well stimulation fluid
(either mud based or organic based) that includes HF or an HF/HCl
mixture into the formation. After allowing the well stimulation
fluid to react with the formation for a predetermined amount of
time, an overflush solution that includes HCl and/or brine (which
can include ammonium or potassium chloride) is injected into the
formation to end the reaction of the stimulation fluid with the
formation. In many instances, the reaction of the acid with the
formation is rapid, frequently instantaneous, thereby limiting the
penetration depth of the acid.
[0008] One difficulty that is frequently encountered with
traditional sandstone stimulation operations that employ HF as a
stimulation fluid is that HF can precipitate into the formation,
typically as a fluoride, thereby causing formation damage and
limiting the efficiency of the matrix stimulation treatment. The
damage caused by fluoride precipitation can be aggravated at the
higher temperatures that are typically encountered in the
formation. Another difficulty encountered with traditional HF
sandstone stimulation is the acid reacts very rapidly with the
formation, often instantaneously, thereby limiting the penetration
of the acid into the formation. Therefore, it would be advantageous
to develop a stimulation fluid and method of using same that reacts
at a slower rate with the formation and which does not form
precipitants upon reaction with the sandstone formation at high
temperatures.
SUMMARY
[0009] Generally, methods and compositions for the stimulation of
sandstone formations are provided.
[0010] In one aspect, a non-acidic well stimulation composition is
provided for use in sandstone formations. The composition includes
an ammonium containing compound; a nitrite containing compound; and
a non-acidic well stimulation fluid.
[0011] In another aspect, a method for stimulating production of
hydrocarbons from a hydrocarbon contacting formation is provided.
The method comprises the steps of injecting an aqueous preflush
solution into the formation that includes a heat generating
composition. The heat generating composition includes ammonium and
nitrite ion containing compounds. In one embodiment, at least one
of the ammonium and nitrite ion containing compounds is
encapsulated with a coating that is erodible such that reaction
between the ammonium and nitrite ions is delayed until the ammonium
and nitrite containing compounds have migrated to within the
formation, thereby allowing the ammonium and nitrite containing
compounds to react and generate heat and nitrogen gas. The method
includes the step of injecting into the formation an acid-free well
stimulation composition that includes sodium hydroxide, ammonium
containing compounds and nitrite containing compounds, wherein the
well stimulation composition is operable to dissolve at least a
portion of the sandstone formation. The acid-free well stimulation
composition reacts with the formation. The method then includes the
step of injecting an overflush solution that includes brine into
the formation such that the overflush solution stops the reaction
between the well stimulation composition and the formation. The
ammonium containing compound and nitrite containing compound
present in the preflush and acid-free well stimulation compositions
are operable to react to produce heat.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 is a graph showing the solubility of sand in sodium
hydroxide as a function of temperature.
[0013] FIG. 2 is a graph showing the thermodynamic profile of the
heat generating reaction according to one embodiment.
[0014] FIG. 3 is a graph showing the pressure profile of the heat
generating reaction according to one embodiment.
DETAILED DESCRIPTION OF THE INVENTION
[0015] Although the following detailed description contains many
specific details for purposes of illustration, it is understood
that one of ordinary skill in the art will appreciate that many
examples, variations and alterations to the following details are
within the scope and spirit of the invention. Accordingly, the
exemplary embodiments of the invention described herein and
provided in the appended figures are set forth without any loss of
generality, and without imposing limitations, on the claimed
invention.
[0016] As used herein, "sandstone" refers to any formation
primarily composed of silica, silicate minerals and various forms
of feldspar and clays. The grains of sandstone rock are
traditionally sand-sized.
[0017] The present invention addresses problems associated with
prior art methods for the stimulation of sandstone formations at
high temperatures, particularly problems encountered when highly
corrosive acids, such as HF, are employed, and provides new
non-acidic stimulation methods. The methods described herein
generally includes a three step process that includes the steps of
injecting a preflush brine, followed by injecting a non-acidic
stimulation solution, and finally injecting an overflush brine.
[0018] Typically, the non-acidic stimulation fluid includes an
alkali or alkaline earth hydroxide, such as sodium hydroxide. In
certain embodiments, the non-acidic stimulation fluid primarily
includes sodium hydroxide. The sodium hydroxide solution reacts
with the sandstone formation much more slowly than typical acidic
stimulation fluids, enabling deeper penetration of the stimulation
fluid into the sandstone formation. Additionally, the sodium
hydroxide solution does not react with the formation in a way that
leads to the formation of precipitates during reaction.
[0019] As used herein, "preflush" refers to a fluid that is pumped
into the wellbore ahead of a main stimulation treatment fluid to
displace ions, such as potassium, sodium, and calcium. In certain
embodiments, the preflush is operable to minimize the possibility
of adverse reactions with the treating fluids and the formation of
unwanted precipitates, which can lead to clogging of the pores of
the formation.
[0020] The preflush solution can include a heat generating
composition that is supplied to the formation for the purpose of
increasing the temperature within the formation. Exemplary
compounds present in the heat generating composition include
ammonium ions and nitrite ions (for example, present as NH.sub.4Cl
and NaNO.sub.2). In certain embodiments, the preflush brine
solution can include halide-containing brines. In one embodiment,
the preflush brine can be aqueous ammonium chloride, having for
example, a concentration range of between about 1 and 20% by
weight, alternatively between about 5 to 10% by weight,
alternatively between 5-7% by weight, alternatively between 7-9% by
weight, or alternatively between 9-10% by weight. In certain
embodiments, prior to injection into the formation, the preflush
brine solution can be preheated to a temperature of up to about
70.degree. C., alternatively up to about 50.degree. C., and
alternatively between about 20.degree. C. and 60.degree. C. Upon
delivery of the heat generating compounds to the formation, the
reactants react to form heat and gas.
[0021] As used here, "overflush" refers to a fluid that is pumped
into the wellbore after the stimulation fluid has been injected
into the formation and the reaction between the stimulation fluid
and the formation is complete. The overflush fluid can also, in
certain embodiments, help to maintain a low pH environment in the
near-wellbore formation, which can help to prevent precipitation of
reaction products as the treatment fluids are removed from the
formation during the flow back phase of the treatment.
[0022] As used herein, "brine" refers to a solid-free aqueous
solution that includes dissolved inorganic salts.
[0023] As used herein, "non-acidic stimulation fluid" refers to a
stimulation fluid that is acid-free that has a pH that is greater
than 7. The terms "non-acidic" and "acid-free" may be used
interchangeably herein. In certain embodiments, the non-acidic
stimulation fluid includes sodium hydroxide.
[0024] In one aspect, a method for injecting a non-acidic
stimulation fluid into a sandstone formation is provided. In one
embodiment, the method consists of three steps: a first step that
includes the injection of a preflush brine solution into the
formation, a second step that includes the injection of a
non-acidic stimulation fluid into the formation, and a third step
that includes the injection of an overflush brine solution into the
formation.
[0025] As used herein, when it is disclosed that the well
stimulation fluid includes sodium hydroxide, it is understood that
in certain embodiments other hydroxide compounds, for example,
calcium hydroxide or potassium hydroxide, may be substituted.
[0026] In certain embodiments, the use of a preflush composition
that includes heat generating compounds is operable to increase the
downhole temperature by at least about 50.degree. C., alternatively
at least about 75.degree. C., alternatively at least about
100.degree. C.
[0027] In certain embodiments, the temperature within the formation
is sufficient to activate the reaction between the compounds in the
heat generating composition.
[0028] In certain embodiments, when the heat generating compounds
can be incorporated with the non-acidic well stimulation fluid, the
presence of the sodium hydroxide helps to prevent a premature
reaction between the ammonium and nitrite containing compounds,
thereby allowing the reactants to reach the formation before the
high temperatures within the formation cause the reaction between
the heat generating compounds.
[0029] The reaction of silicon oxide (SiO.sub.2) with sodium
hydroxide is provided as follows:
SiO.sub.2+2NaOH.fwdarw.Na.sub.2SiO.sub.3+H.sub.2O
[0030] The reaction between the sodium hydroxide and the sandstone
formation is generally slow and does not include precipitation of
any interfering compounds, as is the case with the use of HF
stimulation fluids. At increased temperatures, the reaction between
the sodium hydroxide and the formation is facilitated and more
efficient, and in certain preferred embodiments heat can be
separately supplied to the site of the reaction by other known
means. In alternate embodiments, the non-acidic well stimulation
fluid can be preheated prior to injection into the formation.
[0031] In one embodiment of this invention, the non-acidic
stimulation fluid can include sodium hydroxide. In certain
embodiments, the concentration of the sodium hydroxide solution can
be in a range of between about 2 and 20% by weight, 5 to 15% by
weight, alternatively between 5-8% by weight, alternatively between
8-12% by weight, or alternatively between 12-15% by weight. One
preferred embodiment includes sodium hydroxide of at least 5% by
weight. In a preferred embodiment, sodium hydroxide is at least 10%
by weight. In a more preferred embodiment sodium hydroxide is at
least 15% by weight. The sodium hydroxide solution is generally
injected into the sandstone formation directly following the
injection of the preflush brine, and before the injection of the
overflush brine. In certain embodiments, the sodium hydroxide
solution is allowed to react with the sandstone formation for up to
about 1 hour, alternatively for between about 1 and 2 hours,
alternatively between about 2 and 3 hours, or alternatively for
more than about 3 hours. It is understood, however, that the time
during which the non-acidic stimulation fluid is allowed to react
with the formation can be varied from minutes (for example, 5
minutes, 15 minutes, or 30 minutes) up to several hours (for
example, up to about 12 hours), depending upon the concentration of
the stimulation fluid and the type of formation that is being
treated. In certain embodiments, prior to injection into the
formation, the non-acidic stimulation fluid can be preheated, for
example to a temperature of up to about 70.degree. C.,
alternatively up to about 50.degree. C., alternatively between
about 20.degree. C. and 60.degree. C., prior to injection into the
formation.
[0032] In certain embodiments, the overflush brine solution can be
selected from a group of halide-containing brines. Upon the
injection of the overflush brine solution into the formation, the
reaction between the non-acidic stimulation fluid and the sandstone
formation is terminated, thereby ending penetration of the
stimulation fluid into the formation. In one embodiment, the
overflush brine can be aqueous ammonium chloride in a concentration
range of between about 1 and 5% by weight, alternatively between
about 5 to 10% by weight, alternatively between 5-7% by weight,
alternatively between 7-9% by weight, or alternatively between
9-10% by weight, or alternatively between about 10 and 15% by
weight. In certain embodiments, the preflush and overflush brines
may have the same composition.
[0033] As noted above, in certain embodiments of this invention,
any of the fluids that are injected into the sandstone formation,
selected from the group that includes the preflush, stimulation and
overflush fluids, can be preheated to a temperature of between
about 20 to 70.degree. C., prior to injection. In certain
embodiments, only the sodium hydroxide containing non-acidic
stimulation fluid is preheated before injection, as the higher
temperature may enhance the stimulation efficiency of the
stimulation fluid solution by enabling a slower reaction time with
and deeper penetration into the formation rock.
[0034] In certain embodiments, the non-acidic well stimulation
techniques and compounds described herein can be coupled with
traditional hydraulic fracturing techniques. In certain
embodiments, the non-acidic stimulation fluids can be used to treat
solids.
[0035] In one embodiment, a method is provided for injecting a
stimulation fluid into a sandstone formation. The method utilizes
the step of the co-injection the heat generating composition. In
certain embodiments, the heat generating composition takes
advantage of an oxidation-reduction reaction (also referred to
herein as a ReDox composition) for the in-situ generation of heat
within the formation to provide a means for heating the stimulation
fluid. Additionally, the reaction of components of the heat
generating composition can generate substantial volumes of nitrogen
gas and create an area localized pressure within the formation,
which in turn can cause micro-fracturing of the nearby stata to
improve permeability of near fracture surface of the formation. In
certain embodiments, the method can include the step of supplying a
composition that includes compounds that include ammonium ions and
nitrite ions to the formation, which can react exothermically and
generate heat and gaseous nitrogen. In certain embodiments, all or
a portion of the oxidation-reduction composition can be
incorporated with fracturing fluids and injected during a hydraulic
fracturing treatment. In certain embodiments, a portion of the heat
generating composition can be injected into the formation along
with or after the injection of the preflush and ahead of the
non-acidic stimulation fluid.
[0036] The in-situ generation of heat and nitrogen (and resulting
increase in pressure within the formation at the reaction site),
can increase the permeability of certain gas formations. The heat
and gas that are generated by the reaction can cause tensile and
thermal fractures within the hydraulically induced and within the
existing fractures in the formation. It is understood that the
generation of the microfractures within the formation may depend on
the type of formation being treated. This, coupled with the
administration of the non-acidic well stimulation fluid described
herein (such as a sodium hydroxide based fluid), can result in the
increased production from the formation as both the heat generating
composition and the non-acidic well stimulation fluid act on the
formation in a manner that results in increased permeability.
[0037] In certain embodiments, the heat generating composition
releases significant quantities of nitrogen gas within the
formation, which then migrates into the fractures within the
formation to form additional microfractures within the formation.
The heat generating composition fluids, such as a composition that
includes an ammonium compound, a nitrite compound and optionally an
activator, are injected to the formation where it migrates within
large fractures. Upon reaction, the injected fluids produce heat
and nitrogen gas, thereby causing microfractures to develop within
the formation, providing pathways for migration of the non-acidic
stimulation fluid to enter the formation and for the hydrocarbon
molecules trapped within the formation to migrate out of the
formation and be recovered.
[0038] In yet another embodiment, a composition that includes
ammonium ions, nitrite ions, and an activator can be injected into
the formation with the preflush brine, wherein at least one of the
ammonium ions and/or nitrite ions is optionally encapsulated. It is
understood that ammonium ions and nitrite ions as used herein
refers to an ionic compound wherein a counter ion is included. For
example, ammonium ions can be supplied as ammonium chloride.
Polymers, that are hydrated, may be used to coat at least one
reactant, for example NaNO.sub.2. Exemplary hydrated polymers can
include guar, chitosan and polyvinyl alcohol. Other binders, such
as carboxymethyl cellulose or xanthan, may also be used as coating
material, such as for at least one reactant such as NH.sub.4Cl. The
formation temperature will trigger the release of reactants from
the coating polymer or binder. The heat of the formation, the
activator, water for the formation, and the non-acidic well
stimulation fluid can all play a role in the erosion or removal of
the encapsulating material, which then leads to a reaction between
the components and the subsequent generation of heat and gas. Upon
encountering water or heat, the coating on one or both of the
ammonium or nitrite containing compound dissolves, thereby allowing
the reactants to react with each other.
[0039] Certain embodiments of the methods and composition described
herein are responsible for the release of kinetic energy and
thermal energy, which is a result of the exothermic nature of the
oxidation-reduction reaction. In one embodiment, for example,
aqueous solutions of NH.sub.4Cl and NaNO.sub.2 can be mixed in the
presence of an activator to generate heat, nitrogen gas, NaCl, and
water. The generation of nitrogen gas, along with the resulting
increased temperature, can result in an increase in the local
pressure and the development of microfractures in the tight
formation. The heat that is generated, as noted previously, assists
with the reaction between the non-acidic well stimulation fluid and
the formation.
[0040] In typical usage, the reaction between NH.sub.4Cl and
NaNO.sub.2 in the presence of an activator results in local
generation of about 60 L of nitrogen per liter of reactants and
about 225 Kcal of heat per liter of reactants. In certain
embodiments, the reaction of ammonium ions and nitrite ions can
result in the generation of at least about 50 Kcal of heat per
liter of reactants, alternatively at least about 100 Kcal of heat
per liter of reactants, alternatively at least about 150 Kcal of
heat per liter of reactants, alternatively at least about 200 Kcal
of heat per liter of reactants. It is believed that the increased
pressure and temperature are sufficient to overcome the tensile
strength of the formation, thereby leading to creation of tensile
microfractures in the formation.
[0041] As shown in FIG. 1, the solubility of a sandstone formation
in sodium hydroxide is shown as a function of temperature,
demonstrating that sand has greater solubility in sodium hydroxide
at higher temperatures, as well as at higher concentrations of
sodium hydroxide. For example, solubility is shown to increase in a
5% NaOH solution from less than about 2.55 by weight to over 3% by
weight over a 3 hour period at temperatures of about 25.degree. C.
and 55.degree. C., respectively. A more concentrated 15% solution
at a temperature of about 70.degree. C. demonstrated a solubility
of greater than about 4.5% by weight over a 3 hour period.
[0042] FIG. 2 shows the generation of heat as a function of time
for the reaction of equimolar amounts of ammonium chloride and
sodium nitrite. As shown, the temperature rises rapidly to a peak
within about 10 minutes of reaction, maintaining an elevated
temperature for approximately 20 minutes, and slowly cooling over
the next 30 minutes. FIG. 2 provides a proof of concept that the
temperature increases as a result of an exothermic reaction and
that the reaction may be designed to reach a required temperature
such that thermal fractures are created.
[0043] FIG. 3 provides a graph showing the amount of pressure
generated by the reaction of ammonium chloride and sodium nitrite.
The test was run in a high temperature, high pressure press. Prior
to initiating the reaction, the press was set at 200 psi. The
reaction showed that the pressure gradually increased by about 200
psi during the reaction. FIG. 3 demonstrates that the pressure
increase is due to the nitrogen gas generated as a result of the
chemical reaction, and is a function of reactants
concentration.
[0044] In an alternate embodiment, a multi-component composition
that includes at least one ammonium containing compound and at
least one nitrite containing compound can be injected into a
formation, wherein at least one component can be encapsulated with
a binder to form a solid matrix with the component. Exemplary
encapsulating binders include 55-carboxymethyl cellulose, xanthan,
and like compounds. Exemplary binders are preferably reactive with
water or the non-acidic well stimulation fluid, and/or heat such
that upon contact with well stimulation fluid or water, or upon
heating, the binder erodes or dissolves, thereby allowing the
reactants to react.
[0045] In another embodiment, a proppant can be suspended in the
well stimulation fluid and can be injected into a formation. Along
with the well stimulation fluid, a heat generating composition that
includes at least one ammonium containing compound, at least one
nitrite containing compound and optionally an activator, can be
injected into the formation. In certain preferred embodiments, at
least one of the ammonium containing compound and nitrite
containing compound is encapsulated. In certain embodiments, a
solution that includes the ammonium and nitrite ion containing
composition can be injected directly into the formation before the
well stimulation fluid is injected. In certain embodiments, the
ammonium and nitrite ion containing solution can be injected into
the formation approximately 5 minutes before the injection of the
well stimulation fluid, alternatively approximately 10 minutes
before injection of the well stimulation fluid, alternatively
approximately 15 minutes before injection of the well stimulation
fluid. The water and/or the heat of the formation can facilitate
erosion of the encapsulating material such that the reaction
between the ammonium and nitrite containing compounds is delayed,
thereby allowing the heat generating composition to migrate and
seep into the fractures within the formation.
[0046] In another embodiment, an aqueous composition that includes
ammonium ions, nitrite ions, a non-acidic well stimulation fluid,
and optionally a buffer, are injected into a formation in a well
stimulation or a hydraulic fracturing procedure.
[0047] For each of the embodiments described herein, exemplary
ammonium ions include ammonium chloride, ammonium bromide, ammonium
nitrate, ammonium sulfate, ammonium carbonate, ammonium hydroxide,
and the like.
[0048] Exemplary combinations of reactants for the heat generating
composition can include: urea and sodium hypochlorite; urea and
sodium nitrite; ammonium hydroxide and sodium hypochlorite; and
ammonium chloride and sodium nitrite.
[0049] In certain embodiments, the heat generating composition
includes equal molar amounts of the ammonium containing compound
and the nitrite containing compound when they are supplied to the
formation to ensure complete reaction of both components. In
alternate embodiments, up to about a 5% excess of either component
can be employed, however it is generally preferred that equimolar
amounts are employed. Thus, in certain embodiments, the ratio of
ammonium to nitrite in the compositions disclosed herein can range
from between about 1.1:1 to 1:1.1; alternatively between about
1.05:1 and 1:1.05, alternatively about 1:1.
[0050] In certain embodiments, the procedures described herein can
utilize the elevated temperatures within the formation as the
activator for the reaction. For example, in certain embodiments,
the temperature within the formation may be at least about
60-70.degree. C. Typical formation temperatures are about
200.degree. F. or higher.
[0051] In certain embodiments, the fluids used in this application
can include certain chemical additives that can help to form a
viscous fracturing fluid. The chemical additives can include at
least one solvent and at least one polymer that is soluble in the
solvent.
[0052] Generally, during successful hydraulic fracturing
procedures, the fracturing liquid must be removed from the well
upon completion of the stimulation treatment. The process can be
both costly and time consuming. Advantageously, the compositions
and methods described herein are designed to cause no damage to the
formation, which is a challenge considering the current fracturing
technologies. To overcome this problem, the compositions and
methods described herein advantageously utilize novel combinations
of nitrogen generating chemicals as the hydraulic fracturing
liquid-base. Thus, in certain embodiments, the liquids used for
fracturing of the formation, which can include the nitrogen
generating chemicals previously described, can be injected into the
formation though the wellbore or other injection means at a
sufficiently high injection rate so as to create pressures within
the formation that can effectively fracture the rock or open
previously existing fractures. As the fracturing liquid seeps into
the formation, these nitrogen generating chemicals can be triggered
to react, thereby generating large amounts of nitrogen gas and heat
within the formation and near the newly created fracture surfaces.
In certain embodiments, the triggering mechanism can be the heat of
the formation temperature. In alternate embodiments, the triggering
mechanism can be an injected fluid, such as an acid, that can be
injected at the end of the fracturing process. The generated
nitrogen gas and heat can create additional microfractures and
thermal fractures at or near the fracture formed as a result of the
hydraulic fracturing. The reaction generates at least about 200
Kcal and 50 L of nitrogen gas per liter of the heat generating
chemicals that is supplied to the reaction, alternatively about 225
Kcal and 60 L of nitrogen per liter of the heat generating
chemicals supplied to the reaction.
[0053] In certain embodiments, the heat generating compounds can be
supplied to the formation separately, for either the preflush
fluids or the well stimulation fluids. For example, in certain
embodiments, the preflush fluids that include brine and an ammonium
containing compound can be injected into the formation. Following
injection of the preflush fluids, a nitrite containing compound can
be injected into the formation and the ammonium and nitrite
compounds can react to produce heat and nitrogen gas. Alternately,
in another embodiment, the preflush fluids can include brine and a
nitrite containing compound. These preflush fluids are injected
into the formation, followed by the injection of an ammonium
containing compound, thereby allowing the nitrite and ammonium
compounds to react to produce heat and nitrogen gas.
[0054] In certain embodiments, a polymer can be mixed with ammonium
solution, nitrite solution, or a combination thereof, and can serve
as the base fluid being injected in the formation. Thus, in certain
embodiments, the non-acidic stimulation fluid can include a solvent
base, such as water, a polymer viscosifying agent, and an ammonium
containing compound. In such an embodiment, following the injection
of the fracturing fluid, a nitrite containing compound can be
injected into the formation.
[0055] In an alternate embodiment, the non-acidic well stimulation
fluid can include a solvent base, such as water, a polymer
viscosifying agent, and a nitrite containing compound. In such an
embodiment, following the injection of the non-acidic well
stimulation fluid, an ammonium containing compound would then be
injected into the formation.
[0056] Advantageously, in contrast to some currently employed
stimulation methods, the methods and compositions described herein
do not produce any damaging by-products as a result of the in-situ
reaction. For example, the acids utilized as activators are
typically consumed by the reaction and are only present in
relatively small quantities such that there is little or no
residual acid remaining that may cause environmental concerns. As a
result, following the stimulation procedure, no clean-up procedure
is required. Thus, through the creation of the synthetic
sweetspots, maximum enhancement of gas production with a minimal
creation of damaging waste products is provided.
[0057] In certain embodiments, the methods and compositions
described herein advantageously and unexpectedly eliminate
formation damage that can be caused by a fracturing gel, water
blockage, and/or condensate banking. These conditions result in
reduced permeability of fluids within the formation, and
subsequently lead to poor production of a well. The generation of
the synthetic sweet spot according to the methods described herein
avoids these problems.
[0058] In certain embodiments, the methods and compositions
described herein advantageously and unexpectedly can be used to
stimulate injector and producer wells, particularly in a sandstone
formation.
[0059] The methods and compositions provided herein solve several
problems that are frequently encountered during the construction of
commercial wells in formations where acid stimulation is
utilized.
[0060] First, problems associated with damage to the formation
caused by current strong acid stimulation methods can be
eliminated. For example, the methods and compositions described
herein, advantageously help to eliminate the production of
precipitates that can be locked near a recently created fracture
surface by creating many tensile fractures near the fracture
surface such that any filtrate readily flows through these
fractures toward the well.
[0061] Second, the methods and compositions provided herein,
advantageously enhance production over traditional strong acid
stimulation methods through the slower reaction rates of the
hydroxide compounds with the formation, allowing for controlled
reaction such that new flow channels are created.
[0062] Finally, current strong acid stimulation techniques may
require many fracturing stages to create sufficient reservoir
volume contact within the well to be commercial are eliminated as a
result of the production of microfractures due to the gas and heat
that are produced. By reducing the number of required fracturing
stages for the same production, the present stimulation treatment
described herein is both more cost effective and accomplished more
quickly; thereby providing viable economical options for the
stimulation of low producing wells.
[0063] Although the present invention has been described in detail,
it should be understood that various changes, substitutions, and
alterations can be made hereupon without departing from the
principle and scope of the invention. Accordingly, the scope of the
present invention should be determined by the following claims and
their appropriate legal equivalents.
[0064] The singular forms "a", "an", and "the" include plural
referents, unless the context clearly dictates otherwise.
[0065] Optional or optionally means that the subsequently described
event or circumstances may or may not occur. The description
includes instances where the event or circumstance occurs and
instances where it does not occur.
[0066] Ranges may be expressed herein as from about one particular
value, and/or to about another particular value. When such a range
is expressed, it is to be understood that another embodiment is
from the one particular value and/or to the other particular value,
along with all combinations within said range.
[0067] Throughout this application, where patents or publications
are referenced, the disclosures of these references in their
entireties are intended to be incorporated by reference into this
application, in order to more fully describe the state of the art
to which the invention pertains, except when these references
contradict the statements made herein.
[0068] As used herein and in the appended claims, the words
"comprise," "has," and "include" and all grammatical variations
thereof are each intended to have an open, non-limiting meaning
that does not exclude additional elements or steps.
[0069] As used herein, terms such as "first" and "second" are
arbitrarily assigned and are merely intended to differentiate
between two or more components of an apparatus. It is to be
understood that the words "first" and "second" serve no other
purpose and are not part of the name or description of the
component, nor do they necessarily define a relative location or
position of the component. Furthermore, it is to be understood that
that the mere use of the term "first" and "second" does not require
that there be any "third" component, although that possibility is
contemplated under the scope of the present invention.
* * * * *